Citation to references in this discussion are to a References section found at the end of this Specification. Injection of carbon dioxide (CO2) to produce the residual oil from oil-bearing formations has been practiced for many years. CO2, if injected under miscible conditions, may significantly reduce oil viscosity, which enables a greater percentage recovery of oil in place. CO2 flooding is one technique for enhanced or tertiary recovery of oil. These designations apply because the injection of CO2 classically follows primary and secondary (water flood) stages of production from an oil reservoir. Even so, the advantageous characteristics of low viscosity and density result in problems of their own due to the low mobility ratio of CO2, which results from the relatively low density and low viscosity of CO2. These characteristics encourage flow-segregation into areas of reservoir rock such that other areas of reservoir rock are not swept. By way of example, the segregation is associated with such problems as viscous fingering and gravity override, resulting in poor vertical sweep and poor aerial sweep efficiencies. The problem of viscous fingering is associated with an unnecessarily early breakthrough of the CO2 front. This happens because injected CO2 has a problematic tendency to segregate into high permeability streaks that maybe found within reservoir rocks, such as rock matrix structure in zones having a high inherent permeability as compared to other zones of rock, or zones of fractured rock. Gravity segregation is another problem caused by low density of CO2 which can result in gravity override such that the flood does not sweep lower portions of the rock (Green and Willhite, 1998). Thus, the reduced sweep efficiency impairs ultimate recovery of oil in place because the CO2 simply bypasses portions of the reservoir rock. In other instances, gravity causes the CO2 segregate into the upper portion of reservoir rock, such that lower portions are not swept.
CO2 has many advantages over other gases such as nitrogen. Particular advantages of CO2 include an ability to achieve a supercritical state at most reservoir conditions of pressure and temperature, together with crude oil miscibility where CO2 dissolves into crude oil with consequent beneficial reduction of oil viscosity. CO2 injection, otherwise known as CO2 flooding, may be alternatively designed to perform as a miscible flood or an immiscible flood.
Different methods have been proposed to combat the aforementioned problems. One such solution is the injection of slugs of water alternating with CO2, i.e. water alternating gas or WAG. This technique increases the water saturation of the pores and reduces the CO2 saturation, but does not improve the mobility ratio problem of the CO2 portion of the flood. The WAG technique problematically results in reduced injectivity of both CO2 and water (Christensen, Stenby and Skauge, 2012; Ghahfarokhi, Pennell, Matson, and Linroth, M. 2016).
CO2 foam has been proposed as another a solution to these problems (Bond & Hollbrook, 1958). These foams may be surfactant-based, i.e., as a colloidal dispersion of gas in a matrix of surfactant and water. As used herein, a “foam” is a gas or supercritical fluid dispersed in a liquid. By way of example, it is possible to construct a CO2 foam as CO2 bubbles in the form of gas or supercritical CO2 separated by a liquid film having perhaps from 60% to 97% CO2 content by volume of the CO2 bubbles. Addition of certain non-ionic surfactants aid in the generation of foam, especially if the surfactants are at least partially CO2 soluble (Micha, Wei, Sung, Eastoe, Trickett and Mohamed, 2010). The use of foam may beneficially reduce mobility of the CO2 by up to 100 times that of injected CO2 alone. The reduction of CO2 mobility occurs because the foam is less permeable and more viscous than CO2 alone (Syandansk & Zeron, 2011). Also, CO2 foams advantageously have shear thinning characteristics and may be made from environmentally friendly materials.
Nonetheless, problems exist such that these CO2 foams do not enjoy widespread use. Surfactant generated CO2 foams are known to be thermodynamically unstable. These foams also incur adsorption loss of surfactant to the formation rock (Enick & Olsen, 2012). Thickeners used as viscosifying agents for the CO2 have been addressed to improve the mobility control, as have silica nanoparticles. By way of example, certain polymer additives may increase CO2 viscosity up to ten times. Even so, use of these thickeners implicates use of specialized equipment, such as high pressure mixing tanks. The thickeners are also associated with such problems as permeability reduction due to polymer retention by the reservoir rock, especially when these polymers encounter water.
Other researchers have reported investigating nanoparticle-stabilized CO2 foams that may be formed without the use of surfactants (Yu, An, Mo, Liu and Lee, 2″ Foam Mobility Control for Nanoparticle-Stabilized CO2 Foam,” in SPE Improved Oil recovery symposium, Oklahoma, 2012; Yu, Liu, and Lee, “Generation of Nanoparticle-Stabilized Supercritical CO2 Foams,” in Carbon Management Technology Conference, Orlando, 2012; Nguyen, Fadaei and Sinton, 2014). Yu et al. reported that the adhesion energy of the nanoparticle system at the fluid interface is much higher than the surfactant and hence are able to generate longer lasting foams. Various other aspects of the nanoparticle stabilized foams, such as the effect of salinity on the particle size of the nanoparticles, has been established by Alejandro, Caldelas, Johnston, Bryant and Huh, 2010.
Polyelectrolytes materials are capable of forming nanoparticles, especially by virtue of electrostatic interactions between cationic and anionic polyelectrolytes (Koetz and Kosmella, 2006; Koetz, Kosmella and Beitz, 2001; Kristen and Klitzing, 2010; Taylor, Thomas and Penfold, (2007). Polyelectrolytes are a class of polymers known to the art. Formed of repeating electrolyte units that dissociate in an aqueous solution, the units become charged when mixed with water. Acid or base materials may be added to adjust pH. The repeating units may be either linear or branched. Addition of polyelectrolytes to surfactant solutions may reduce the adsorption of surfactants in unconventional reservoirs (He, Yue, Fan and Xu, 2015).